Crude Oil ( ) Brent Crude ( ) Natural Gas ( ) S&P 500 ( ) PHLX Oil ( )

Oasis Petroleum Inc. (OAS) (“Oasis” or the “Company”) today announced financial results for the quarter ended September 30, 2014 and provided an operational update.

Highlights include:

  • Increased average daily production to 45,873 barrels of oil equivalent per day (“Boepd”), a 39% increase over the third quarter of 2013 and a 5% sequential quarter increase.
  • Grew Adjusted EBITDA to $238.8 million in the third quarter of 2014, an increase of $19.2 million over the third quarter of 2013. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.
  • Invested capital expenditures (“CapEx”) of $437.6 million in the third quarter of 2014.
  • Completed and placed on production 66 gross (52.4 net) operated wells in the third quarter of 2014.

“We continue to test a number of things to delineate and optimize results across our extensive acreage position. We have realized some great results from our slickwater completion program, for example,” said Thomas B. Nusz, Oasis’ Chairman and Chief Executive Officer.  “While still in early days, results in the White unit in Indian Hills are very encouraging, including a total of seven wells completed with slickwater stimulation through the entire Bakken and Three Forks section. The single Middle Bakken well has produced nearly 37,000 barrels of oil equivalent through 25 days, which is approximately 51% over our 750 Mboe Middle Bakken type curve for the area.  The six Three Forks wells, including the lower benches, have produced on average approximately 40% better than the top end of our 600 Mboe Three Forks type curve.  Given these results, as well as positive results we are seeing with high volume proppant jobs, we continue to plan on completing over 30% of our wells in the second half of 2014 with increased intensity completions, with most of those wells coming on in the fourth quarter.  Based on our results combined with tests completed by peers, we believe the productivity gains should improve well economics and our Company’s capital efficiency.”

Mr. Nusz added, “We are continuing to gain a better understanding of what our large acreage position can deliver, as our drilling program has made a significant transition to full field development in the last two quarters. At the same time, we have experienced some constraints. Three main items have impacted some of our short-term operational results, but in no means impact our view of the overall quality of our asset base. We experienced production delays in the third quarter due to the interdependency of pad development operations, road restrictions, and less than expected production from lower bench Three Forks wells in North Cottonwood.  We have taken lessons learned from some of the early development work, we are adding infrastructure, and we are in a better position to forecast volumes from our drilling program with much of our delineation work now complete.  Looking forward, as we take into consideration pad cycle time and weather delays, we anticipate completing about 15 less gross operated wells than our 2014 budget, as we pushed out some completions into 2015.  With this in mind, we anticipate producing between 47,000 to 49,000 Boepd in the fourth quarter, which will result in aggregate year over year growth of approximately 35%.”

Taylor Reid, Oasis’ President and Chief Operating Officer added, “With the advances we have made during this transition, we are in a better position as we head into 2015 to execute our full development program and improve operational performance.  Our position in the core of the Bakken, combined with the talented people at Oasis, will enable us to continue our growth trajectory as we implement our capital plan.”

Operational and Financial Update

The Company’s average daily production by project area is listed in the following table:

Quarter Ended:

9/30/2014

6/30/2014

9/30/2013

Average daily production (Boepd)

West Williston

31,429

30,381

19,259

East Nesson

14,444

13,287

11,043

Sanish (1)

2,762

Total

45,873

43,668

33,064

Percent Oil

89.3%

89.1%

89.3%

(1)

Includes production from certain non-operated properties in the Company’s Sanish project area and other non-operated leases adjacent to its Sanish position until the properties were sold in March 2014 (the “Sanish Divestiture”).

The following table describes the Company’s producing wells by project area in the Williston Basin as of September 30, 2014:

Bakken/Three Forks Producing Wells

West Williston

East Nesson

Total Williston Basin

Gross

Net

Gross

Net

Gross

Net

Producing on or before 6/30/2014: (1)

Operated

364

280.5

173

135.6

537

416.1

Non-Operated

176

14.1

101

7.2

277

21.3

Production started in Q3 2014:

Operated

24

17.7

42

34.7

66

52.4

Non-Operated

11

0.5

2

13

0.5

Total Producing Wells on 9/30/2014:

Operated

388

298.2

215

170.3

603

468.5

Non-Operated

187

14.6

103

7.2

290

21.8

(1)

Well counts include changes that occurred in the current reporting period for wells producing on or before June 30, 2014.

Additionally, the Company had 16 rigs running during the third quarter of 2014, and as of September 30, 2014, had an inventory of gross operated wells waiting on completion of 49 wells in West Williston and 12 wells in East Nesson.

The Company’s average price per barrel of oil, without derivative settlements, was $87.17 in the third quarter of 2014, compared to $100.75 in the third quarter of 2013 and $94.48 in the second quarter of 2014. The Company’s average price differential compared to NYMEX West Texas Intermediate (“WTI”) crude oil index prices was 10% in the third quarter of 2014, compared to 5% in the third quarter of 2013 and 8% in the second quarter of 2014.

The Company’s revenues are detailed in the following table:

Quarter Ended:

9/30/2014

6/30/2014

9/30/2013

Revenues ($ in thousands):

Oil

$

328,548

$

334,559

$

273,663

Natural gas

16,158

19,623

13,289

Well services (OWS)

20,925

14,878

17,090

Midstream (OMS)

3,028

3,318

1,456

Total revenues

$

368,659

$

372,378

$

305,498

The Company’s operating expenses are detailed in the following table:

Quarter Ended:

9/30/2014

6/30/2014

9/30/2013

Operating expenses ($ in thousands):

Lease operating expenses (LOE)

$

44,361

$

40,553

$

21,831

Well services (OWS)

13,572

7,200

9,929

Midstream (OMS)

1,350

1,569

390

    Marketing, transportation and gathering expenses (1)

7,048

6,996

5,173

       Non-cash valuation charges

258

118

515

   Total operating expenses

$

66,589

$

56,436

$

37,838

Operating expenses ($ per Boe):

Lease operating expenses (LOE)

$

10.51

$

10.21

$

7.18

    Marketing, transportation and gathering expenses (1)

1.67

1.76

1.70

(1)

Excludes non-cash valuation charges on pipeline imbalances.

The sequential quarter-over-quarter increase in lease operating expenses (“LOE”) per barrel of oil equivalent (“Boe”) was primarily due to higher produced water volumes on wells coming on during the quarter, the operational impact of a lightning strike at one of the Company’s salt water disposal locations, and higher LOE on non-operated volumes.

The increase in marketing, transportation and gathering expenses from the second quarter of 2014 to the third quarter of 2014 is primarily due to higher operated volumes flowing through third-party oil gathering pipelines in the third quarter of 2014. Currently, the Company is flowing 77% of its gross operated oil production through these gathering systems. While transporting volumes through third-party oil gathering pipelines increases marketing, transportation and gathering expenses, it improves oil price realizations by reducing transportation costs included in the Company’s oil price differential for sales at the wellhead.

Production taxes as a percentage of oil and gas revenues were 10.0% in the third quarter of 2014, 9.4% in the third quarter of 2013 and 9.7% in the second quarter of 2014. The Company’s production tax rate increased in the third quarter of 2014 compared to the third quarter of 2013 due to the increased weighting of production in North Dakota compared to Montana, which has lower production tax rates.

Depreciation, depletion and amortization expenses (“DD&A”) totaled $107.0 million in the third quarter of 2014, $72.7 million in the third quarter of 2013 and $97.3 million in the second quarter of 2014. DD&A was $25.35 per Boe in the third quarter of 2014, $23.91 per Boe in the third quarter of 2013 and $24.48 per Boe in the second quarter of 2014.

General and administrative (“G&A”) expenses totaled $23.9 million in the third quarter of 2014, $16.7 million in the third quarter of 2013 and $20.8 million in the second quarter of 2014. Of the $3.1 million sequential quarter-over-quarter increase in G&A expenses, approximately $1.9 million was due to the impact of the Company’s personnel growth and associated employee compensation and approximately $0.9 million was due to the amortization of restricted stock awards and performance share units. G&A expenses were $5.67 per Boe in the third quarter of 2014, $5.50 per Boe in the third quarter of 2013 and $5.22 per Boe in the second quarter of 2014. Amortization of stock-based compensation, which is included in G&A expenses, was $6.1 million, or $1.44 per Boe, in the third quarter of 2014 as compared to $3.0 million, or $1.00 per Boe, in the third quarter of 2013 and $5.2 million, or $1.30 per Boe, in the second quarter of 2014.

The Company’s derivative activities are detailed in the following table:

Quarter Ended:

9/30/2014

6/30/2014

9/30/2013

Derivative activities (1) ($ in thousands)

Derivative settlements

$

(11,129)

$

(11,405)

$

(8,067)

Non-cash change in fair value of derivative instruments

114,555

(54,165)

(31,750)

Net gain (loss) on derivative instruments

$

103,426

$

(65,570)

$

(39,817)

(1)

The Company’s derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.

Interest expense was $39.4 million for the third quarter of 2014 compared to $22.9 million for the third quarter of 2013 and $39.0 million for the second quarter of 2014. The $0.4 million increase from the second quarter of 2014 was primarily due to higher weighted average borrowings under the Company’s revolving credit facility in the third quarter of 2014. Capitalized interest totaled $2.3 million for the third quarter of 2014, $1.4 million for the third quarter of 2013 and $2.3 million for the second quarter of 2014.

Income tax expense was $76.5 million for the three months ended September 30, 2014, resulting in an effective tax rate of 38.6%. The Company’s income tax expense for the three months ended September 30, 2013 was recorded at 38.2% of pre-tax net income. The Company’s effective tax rate is expected to continue to closely approximate the statutory rate applicable to the U.S. and the blended rate for each of the states in which the Company conducts business.

Adjusted EBITDA for the third quarter of 2014 was $238.8 million, a 9% increase over the third quarter of 2013 of $219.6 million, and a decrease of 6% from the second quarter of 2014 of $254.7 million. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.

For the third quarter of 2014, the Company reported net income of $121.6 million, or $1.21 per diluted share, as compared to net income of $54.5 million, or $0.59 per diluted share, for the third quarter of 2013. The Company’s third quarter 2014 results were impacted by several non-cash items, including a $114.6 million non-cash mark-to-market gain on derivative instruments. Excluding these items and their tax effect, the third quarter 2014 Adjusted Net Income (non-GAAP) was $52.3 million, or $0.52 per diluted share. Excluding similar non-cash items and their tax effect, Adjusted Net Income (non-GAAP) for the third quarter of 2013 was $74.5 million, or $0.80 per diluted share. For a definition of Adjusted Net Income and a reconciliation of net income to Adjusted Net Income, see “Non-GAAP Financial Measures” below.

Capital Expenditures

The following table depicts the Company’s exploration and production (“E&P”) CapEx by project area and total CapEx by category:

1Q 2014

2Q 2014

3Q 2014

YTD 2014

CapEx ($ in thousands):

E&P CapEx by Project Area

West Williston

$

189,288

$

223,526

$

244,933

$

657,747

East Nesson

107,843

103,370

174,644

385,857

      Total E&P CapEx (1)

297,131

326,896

419,577

1,043,604

OWS

6,410

18,903

9,070

34,383

Non E&P (2)

3,957

6,036

8,921

18,914

Total Company CapEx (3)

$

307,498

$

351,835

$

437,568

$

1,096,901

(1)

Year-to-date total E&P CapEx includes $27.8 million for Oasis Midstream Services (“OMS”), primarily related to pipelines and salt water disposal systems.

(2)

Non-E&P CapEx includes such items as administrative capital and capitalized interest.

(3)

CapEx reflected in the table above differs from the amounts shown in the statement of cash flows in the Company’s condensed consolidated financial statements because amounts reflected in the table above include accrued liabilities for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.

Liquidity

On September 30, 2014, Oasis had total cash and cash equivalents of $67.2 million. As of September 30, 2014, the Company had $350.0 million of LIBOR loans and $5.2 million of outstanding letters of credit issued under its revolving credit facility, resulting in an unused borrowing base capacity of $1,144.8 million.

Update to Outlook for Operating Metrics

Oasis is updating its full year 2014 guidance on operational metrics:

Metrics

Prior Guidance

Updated Guidance

   Average Daily Production (MBoepd)

      Full Year

46.0 – 50.0

44.9 – 45.4

      4Q14

47.0 – 49.0

   LOE ($ per Boe)

$8.50 – $10.00

$10.00 – $10.50

Hedging Activity

As of November 4, 2014, the Company had the following outstanding commodity derivative contracts, all of which are priced off of WTI and settle monthly:

Weighted Average Prices ($/Bbl)

Remaining Term

Sub-Floor

Floor

Ceiling

Swaps

BOPD

Total Barrels

2014

Full Year

Swaps

Oct – Dec

$

95.90

9,500

874,000

Swaps with sub-floors

Oct – Dec

$

70.00

$

92.60

6,000

552,000

Two-way collars

Oct – Dec

$

95.22

$

106.39

11,500

1,058,000

Three-way collars

Oct – Dec

$

70.59

$

90.59

$

105.25

8,500

782,000

Total 2014 hedges (weighted average)

$

70.34

$

93.25

$

105.91

$

94.62

35,500

3,266,000

2015

Full Year

Swaps

Jan – Dec

$

90.15

10,000

3,650,000

Two-way collars

Jan – Dec

$

86.00

$

103.42

5,000

1,825,000

First Half

Swaps

Jan – Jun

$

91.26

9,000

1,629,000

Deferred puts

Jan – Jun

$

90.00

6,000

1,086,000

Two-way collars

Jan – Jun

$

90.00

$

99.10

2,000

362,000

Total 2015 hedges (weighted average)

$

87.77

$

102.70

$

90.49

23,430

8,552,000

Total 1H15 hedges

32,000

Total 2H15 hedges

15,000

Conference Call Information

Investors, analysts and other interested parties are invited to listen to the conference call:

Date:

Wednesday, November 5, 2014

Time:

10:00 a.m. Central Time

Dial-in:

888-317-6003

Intl. Dial in:

412-317-6061

Conference ID:

7280032

Website:

www.oasispetroleum.com

A recording of the conference call will be available beginning at 12:00 p.m. Central Time on the day of the call and will be available until Wednesday, November 12, 2014 by dialing:

Replay dial-in:

877-344-7529

Intl. replay:

412-317-0088

Replay code:

10054132

The conference call will also be available for replay at www.oasispetroleum.com.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company’s drilling program, production, derivative instruments, capital expenditure levels and other guidance included in this press release. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company’s ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

About Oasis Petroleum Inc.

Oasis is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources, primarily operating in the Williston Basin. For more information, please visit the Company’s website at www.oasispetroleum.com.

Contact:

Oasis Petroleum Inc.
Matt Ultis, (281) 404-9600
Manager – Finance and Investor Relations

 

Oasis Petroleum Inc.

Condensed Consolidated Balance Sheet

(Unaudited)

September 30, 2014

December 31, 2013

(In thousands, except share data)

ASSETS

Current assets

Cash and cash equivalents

$

67,194

$

91,901

Accounts receivable — oil and gas revenues

191,711

175,653

Accounts receivable — joint interest partners

197,929

139,459

Inventory

24,648

20,652

Prepaid expenses

14,253

10,191

Deferred income taxes

6,335

Derivative instruments

33,874

2,264

Advances to joint interest partners

97

760

Other current assets

1,972

391

Total current assets

531,678

447,606

Property, plant and equipment

Oil and gas properties (successful efforts method)

5,546,424

4,528,958

Other property and equipment

261,665

188,468

Less: accumulated depreciation, depletion, amortization and impairment

(933,237)

(637,676)

Total property, plant and equipment, net

4,874,852

4,079,750

Assets held for sale

137,066

Derivative instruments

6,422

1,333

Deferred costs and other assets

44,523

46,169

Total assets

$

5,457,475

$

4,711,924

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities

Accounts payable

$

39,550

$

8,920

Revenues and production taxes payable

248,272

146,741

Accrued liabilities

340,480

241,830

Accrued interest payable

24,902

47,910

Derivative instruments

8,188

Deferred income taxes

9,625

Advances from joint interest partners

6,776

12,829

Total current liabilities

669,605

466,418

Long-term debt

2,550,000

2,535,570

Deferred income taxes

504,735

323,147

Asset retirement obligations

41,052

35,918

Derivative instruments

139

Other liabilities

1,996

2,183

Total liabilities

3,767,388

3,363,375

Commitments and contingencies

Stockholders’ equity

Common stock, $0.01 par value: 300,000,000 shares authorized; 101,614,588 and 100,866,589 shares issued at September 30, 2014 and December 31, 2013, respectively

1,000

996

Treasury stock, at cost: 283,249 and 167,155 shares at September 30, 2014 and December 31, 2013, respectively

(10,602)

(5,362)

Additional paid-in capital

1,001,424

985,023

Retained earnings

698,265

367,892

Total stockholders’ equity

1,690,087

1,348,549

Total liabilities and stockholders’ equity

$

5,457,475

$

4,711,924

 

Oasis Petroleum Inc.

Condensed Consolidated Statement of Operations

(Unaudited)

Three Months Ended September 30,

Nine Months Ended September 30,

2014

2013

2014

2013

(In thousands, except per share data)

Revenues

Oil and gas revenues

$

344,706

$

286,952

$

1,030,735

$

770,445

Well services and midstream revenues

23,953

18,546

59,821

37,939

Total revenues

368,659

305,498

1,090,556

808,384

Expenses

Lease operating expenses

44,361

21,831

124,903

59,586

Well services and midstream operating expenses

14,922

10,319

34,611

19,877

Marketing, transportation and gathering expenses

7,306

5,688

19,606

19,856

Production taxes

34,584

26,823

100,880

70,309

Depreciation, depletion and amortization

106,972

72,728

295,520

205,779

Exploration expenses

1,100

463

1,955

2,712

Impairment of oil and gas properties

1,439

56

2,243

762

General and administrative expenses

23,915

16,728

68,186

47,238

Total expenses

234,599

154,636

647,904

426,119

Gain on sale of properties

43

187,076

Operating income

134,103

150,862

629,728

382,265

Other income (expense)

Net gain (loss) on derivative instruments

103,426

(39,817)

20,253

(41,838)

Interest expense, net of capitalized interest

(39,420)

(22,854)

(118,568)

(65,429)

Other income (expense)

(38)

23

250

1,097

Total other income (expense)

63,968

(62,648)

(98,065)

(106,170)

Income before income taxes

198,071

88,214

531,663

276,095

Income tax expense

76,484

33,715

201,290

102,626

Net income

$

121,587

$

54,499

$

330,373

$

173,469

Earnings per share:

Basic

$

1.22

$

0.59

$

3.32

$

1.88

Diluted

1.21

0.59

3.29

1.87

Weighted average shares outstanding:

Basic

99,715

92,449

99,647

92,408

Diluted

100,306

92,836

100,356

92,838

 

Oasis Petroleum Inc.

Selected Financial and Operational Statistics

(Unaudited)

Three Months Ended September 30,

Nine Months Ended September 30,

2014

2013

2014

2013

Operating results ($ in thousands):

Revenues

Oil

$

328,548

$

273,663

$

972,338

$

737,963

Natural gas

16,158

13,289

58,397

32,482

Well services and midstream

23,953

18,546

59,821

37,939

Total revenues

$

368,659

$

305,498

$

1,090,556

$

808,384

Production data:

Oil (MBbls)

3,769

2,716

10,759

7,687

Natural gas (MMcf)

2,707

1,954

7,752

4,883

Oil equivalents (MBoe)

4,220

3,042

12,051

8,501

Average daily production (Boe/d)

45,873

33,064

44,143

31,140

Average sales prices:

Oil, without derivative settlements (per Bbl) (1)

$

87.17

$

100.75

$

90.37

$

95.24

Oil, with derivative settlements (per Bbl) (1) (2)

84.22

97.78

88.07

94.58

Natural gas (per Mcf) (3)

5.97

6.80

7.53

6.65

Costs and expenses (per Boe of production):

Lease operating expenses

$

10.51

$

7.18

$

10.36

$

7.01

Marketing, transportation and gathering expenses (4)

1.67

1.70

1.66

1.59

Production taxes

8.19

8.82

8.37

8.27

Depreciation, depletion and amortization

25.35

23.91

24.52

24.21

General and administrative expenses

5.67

5.50

5.66

5.56

(1)

For the nine months ended September 30, 2013, average sales prices for oil are calculated using total oil revenues, excluding bulk oil sales of $5.8 million, divided by oil production.

(2)

Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes.

(3)

Natural gas prices include the value for natural gas and natural gas liquids.

(4)

Excludes bulk oil purchase and non-cash valuation charges on pipeline imbalances.

 

Oasis Petroleum Inc.

Condensed Consolidated Statement of Cash Flows

(Unaudited)

Nine Months Ended September 30,

2014

2013

(In thousands)

Cash flows from operating activities:

Net income

$

330,373

$

173,469

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization

295,520

205,779

Gain on sale of properties

(187,076)

Impairment of oil and gas properties

2,243

762

Deferred income taxes

197,548

102,244

Derivative instruments

(20,253)

41,838

Stock-based compensation expenses

15,755

8,411

Deferred financing costs amortization and other

5,209

2,693

Working capital and other changes:

Change in accounts receivable

(62,581)

(67,487)

Change in inventory

(4,089)

(8,820)

Change in prepaid expenses

(3,179)

(5,175)

Change in other current assets

(1,581)

(138)

Change in other assets

(3,069)

(63)

Change in accounts payable and accrued liabilities

108,788

82,246

Change in other liabilities

(116)

922

Net cash provided by operating activities

673,492

536,681

Cash flows from investing activities:

Capital expenditures

(972,763)

(654,175)

Acquisition of oil and gas properties

(26,126)

(133,061)

Increase in restricted cash

(986,210)

Proceeds from sale of properties

324,938

Costs related to sale of properties

(2,337)

Redemptions of short-term investments

25,000

Derivative settlements

(24,773)

(5,135)

Advances from joint interest partners

(6,053)

(7,965)

Net cash used in investing activities

(707,114)

(1,761,546)

Cash flows from financing activities:

Proceeds from issuance of senior notes

1,000,000

Proceeds from revolving credit facility

370,000

160,000

Principal payments on revolving credit facility

(355,570)

Debt issuance costs

(99)

(21,718)

Purchases of treasury stock

(5,240)

(1,424)

Other

(176)

Net cash provided by financing activities

8,915

1,136,858

Decrease in cash and cash equivalents

(24,707)

(88,007)

Cash and cash equivalents:

Beginning of period

91,901

213,447

End of period

$

67,194

$

125,440

Supplemental non-cash transactions:

Change in accrued capital expenditures

$

99,103

$

10,530

Change in asset retirement obligations

5,134

4,173

Non-GAAP Financial Measures

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion, amortization, exploration expenses and other similar non-cash or non-recurring charges. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.

The following table presents reconciliations of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively.

Three Months Ended September 30,

Nine Months Ended September 30,

2014

2013

2014

2013

(In thousands)

Adjusted EBITDA reconciliation to net income:

Net income

$

121,587

$

54,499

$

330,373

$

173,469

Gain on sale of properties

(43)

(187,076)

Non-cash change in fair value of derivative instruments

(114,555)

31,750

(45,026)

36,703

Interest expense

39,420

22,854

118,568

65,429

Depreciation, depletion and amortization

106,972

72,728

295,520

205,779

Impairment of oil and gas properties

1,439

56

2,243

762

Exploration expenses

1,100

463

1,955

2,712

Stock-based compensation expenses

6,077

3,040

15,755

8,411

Income tax expense

76,484

33,715

201,290

102,626

Other non-cash adjustments

351

515

(277)

589

Adjusted EBITDA

$

238,832

$

219,620

$

733,325

$

596,480

Adjusted EBITDA reconciliation to net cash provided by operating activities:

Net cash provided by operating activities

$

187,238

$

178,874

$

673,492

$

536,681

Derivative settlements

(11,129)

(8,067)

(24,773)

(5,135)

Interest expense

39,420

22,854

118,568

65,429

Exploration expenses

1,100

463

1,955

2,712

Deferred financing costs amortization and other

(1,989)

(940)

(5,209)

(2,693)

Current tax expense

(2,369)

(555)

3,742

382

Changes in working capital

26,210

26,476

(34,173)

(1,485)

Other non-cash adjustments

351

515

(277)

589

Adjusted EBITDA

$

238,832

$

219,620

$

733,325

$

596,480

Adjusted Net Income and Adjusted Diluted Earnings Per Share are supplemental non-GAAP financial measures that are used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted Net Income as net income after adjusting first for (1) the impact of certain non-cash and non-recurring items, including non-cash changes in the fair value of derivative instruments, impairment of oil and gas properties, and other similar non-cash and non-recurring charges, and then (2) the non-cash and non-recurring items’ impact on taxes based on the Company’s effective tax rate in the same period. Adjusted Net Income is not a measure of net income as determined by GAAP. The Company defines Adjusted Diluted Earnings Per Share as Adjusted Net Income divided by diluted weighted average shares outstanding.

The following table provides reconciliations of net income (GAAP) to Adjusted Net Income (non-GAAP) and diluted earnings per share (GAAP) to Adjusted Diluted Earnings Per Share (non-GAAP):

Three Months Ended September 30,

Nine Months Ended September 30,

2014

2013

2014

2013

(In thousands, except per share data)

Net income

$

121,587

$

54,499

$

330,373

$

173,469

Non-cash change in fair value of derivative instruments

(114,555)

31,750

(45,026)

36,703

Gain on sale of properties

(43)

(187,076)

Impairment of oil and gas properties

1,439

56

2,243

762

Other non-cash adjustments

351

515

(277)

589

     Tax impact (1)

43,560

(12,329)

87,131

(14,237)

Adjusted Net Income

$

52,339

$

74,491

$

187,368

$

197,286

Diluted earnings per share

$

1.21

$

0.59

$

3.29

$

1.87

Non-cash change in fair value of derivative instruments

(1.14)

0.34

(0.45)

0.40

Gain on sale of properties

(1.86)

Impairment of oil and gas properties

0.01

0.02

0.01

Other non-cash adjustments

0.01

0.01

     Tax impact (1)

0.44

(0.14)

0.87

(0.16)

Adjusted Diluted Earnings Per Share

$

0.52

$

0.80

$

1.87

$

2.13

Diluted weighted average shares outstanding

100,306

92,836

100,356

92,838

Effective tax rate

38.6%

38.2%

37.9%

37.2%

(1)

The tax impact is computed utilizing the Company’s effective tax rate on the adjustments for certain non-cash and non-recurring items.